The proposed gas plants use the oldest, cheapest emissions control method - injecting water into the combustion chamber - requiring massive groundwater extraction. And even with that water, they emit over 8× the federal CO2 standard and qualify to operate only through a pollution exemption most Nova Scotians have never heard of.
Each 300 MW plant would extract up to 175,000 litres of groundwater per hour at peak operation - equivalent to roughly 770 gallons per minute. That water must be pumped from fractured bedrock aquifers through industrial production wells, processed through a demineralization plant, injected into the combustion chambers for NOx control, and then discharged as ~50,000 L/hr of wastewater to surface water.
The water infrastructure required at each site includes:
The estimated lifecycle cost of this water infrastructure across both sites is $36–76 million over the 20-year contract term, including $12–24 million in capital costs and $24–52 million in operating costs (demineralization chemicals, well pump electricity, effluent treatment, monitoring, and maintenance).
The Marshdale EARD's groundwater modelling shows that 18–42% of pumping could come from depleting Cameron Brook. This is not an opposition claim - it is the project proponent's own analysis of what their proposed water extraction would do to a nearby watercourse.
The aquifer at Marshdale is fractured bedrock - a geology type rated medium-to-high risk for arsenic and manganese mobilization when subjected to sustained pumping. Large-scale groundwater extraction from fractured bedrock can change flow patterns, drawing contaminants from rock formations that are stable under natural conditions.
The EARD's stream depletion estimate of 18–42% represents a wide range of uncertainty. What is not uncertain is the direction: pumping 175,000 L/hr from this aquifer will affect nearby surface water. The only question is how much.
The proposed technology - SAC (Simple Annular Combustor) aeroderivative turbines with water injection - is not the only option. Two commercially proven alternatives dramatically reduce or eliminate water demand:
| Technology | NOx Control Method | Process Water Use |
|---|---|---|
| SAC aeroCT (proposed) | Water injection into combustor | 175,000 L/hr per site |
| DLE aeroCT | Premixed lean combustion (dry) | ~0 L/hr |
| RICE engines | Lean burn (closed-loop radiator cooling) | <5 litres/hr |
| RICE with SCR | Lean burn + urea injection for further NOx reduction | ~500–2,000 L/hr |
DLE (Dry Low Emissions) turbines use premixed combustion to achieve low NOx without any water injection. They are the same engine platform as the proposed SAC turbines - just with a different combustor module. GE Vernova's LM6000 PF DLE variant has accumulated over 11 million operating hours worldwide.
RICE (Reciprocating Internal Combustion Engines), such as the Wärtsilä 50SG, use lean-burn combustion in enclosed cylinders that produces approximately 90 ppm NOx without any water injection or aftertreatment. Cooling is closed-loop radiator-based, consuming less than 5 litres per hour. Even if SCR (Selective Catalytic Reduction) is added for stricter NOx limits, the water consumption is roughly 1% of SAC water injection volume.
Both DLE and RICE are explicitly allowed by the IESO-NS RFP. The Functional Specifications (Exhibit T, Section 1) permit "combustion turbine generators or reciprocating engine generators." Neither alternative is a workaround - both are among the technology categories the procurement was designed for.
Water injection into a SAC combustor is the oldest and cheapest method of controlling NOx emissions from gas turbines. It works by lowering the flame temperature, which reduces thermal NOx formation. The turbine hardware is simpler (no premixing fuel nozzles, no staged combustion), and refurbished SAC engines are widely available on the secondary market at lower cost than new-build DLE units.
The cost difference between a water-injection SAC configuration and a DLE configuration is estimated at 5–15% of the turbine package price - roughly $12–54 million across both sites (12 turbine units total). However, this premium is partially or fully offset by the $36–76 million in lifecycle water infrastructure costs that DLE eliminates.
| Cost Category | Water-Injection CT | DLE CT | Difference |
|---|---|---|---|
| Turbine hardware (both sites) | $240–360M | $252–414M | +$12–54M for DLE |
| Water infrastructure capital | $12–24M | ~$1–2M | -$11–22M with DLE |
| Water O&M (20 years) | $24–52M | ~$2–4M | -$22–48M with DLE |
| Net lifecycle cost | $276–436M | $255–420M | DLE saves $0–33M |
In no scenario does the water-injection configuration save enough to justify the environmental impact of 14–19 production wells per site, 175,000 L/hr peak extraction from a fractured bedrock aquifer, and 50,000 L/hr effluent discharge to surface water.
DLE turbines achieve low NOx through carefully controlled premixed combustion. Hydrogen burns hotter and faster than natural gas, destabilizing the lean premix flame. Current DLE technology - including the GE LM6000 - is limited to approximately 35% hydrogen by volume. To burn 100% hydrogen, an engine needs a SAC combustor with water injection for NOx control.
The Tolling Agreement includes language about a "pathway to future operation without fossil fuels." The GE LM6000VELOX is rated for 100% hydrogen - but it uses a SAC combustor with water injection, not DLE. If the plants are to be "hydrogen-ready" for 100% hydrogen, the SAC + water injection configuration is locked in by the laws of combustion physics.
This creates a direct conflict:
There is an important counterpoint: NS Power's own IRP modelling explicitly rejected hydrogen-enabled fast-acting generation as uneconomic. The "pathway to clean fuels" language in the Tolling Agreement is aspirational with no enforcement mechanism, no timeline, and no funding commitment. The community is being asked to accept 20 years of groundwater extraction for a hydrogen future that the province's own utility has modelled and rejected.
Simple-cycle gas turbines are the dirtiest form of gas-fired generation. They convert fuel to electricity at roughly 35% efficiency (the rest is waste heat), compared to 55–60% for combined-cycle plants. Their CO2 emission intensity on natural gas is approximately 531 tonnes per GWh - more than eight times the federal emission intensity standard of 65 t/GWh established by Canada's Clean Electricity Regulations.
On diesel backup fuel (which the RFP allows for up to 25% of operating hours), the emission intensity rises to approximately 777 tonnes per GWh - nearly 12 times the federal standard.
| Fuel | Emission Intensity | vs. 65 t/GWh Federal Standard |
|---|---|---|
| Natural gas | ~531 t CO2/GWh | 8.2× dirtier |
| Diesel (#2 distillate) | ~777 t CO2/GWh | ~12× dirtier |
Canada's Clean Electricity Regulations (SOR/2024-263), published December 2024, cap CO2 emissions from electricity generation. Each generating unit receives an annual tonnage cap calculated from its nameplate capacity and the emission intensity parameter of 65 t CO2/GWh.
For a 300 MW plant, the annual emission cap would be:
300 MW × 65 t/GWh × 8,760 hours × 0.001 = 170,820 tonnes CO2/year
However, Section 3 of the regulation creates a special category called "planned units." If a project meets four milestones by December 31, 2025, and begins construction by December 31, 2027, it is completely exempt from the emission cap until December 31, 2049.
A "planned unit" faces zero federal emission limits from commissioning until the end of 2049. There is no reduced cap, no transitional limit, no phase-in. The exemption is binary: qualify, and you are completely unregulated. Miss the deadline, and you face an annual cap you cannot meet at any realistic operating level.
| New Unit (no exemption) | Planned Unit (with exemption) | |
|---|---|---|
| Emission cap applies | From 2035 | Not until 2050 |
| Years of unregulated operation | 0 (from commissioning) | ~20 years (2030–2050) |
| Can operate as peaker at 25% CF? | No - 2× over cap | Yes - no cap applies |
| Dispatch flexibility | Constrained by tonnage ceiling | Unlimited |
The EARDs project these plants will operate at approximately 25% capacity factor. At that level, a single 300 MW plant on natural gas would emit approximately 349,000 tonnes of CO2 per year - more than double the 170,820-tonne federal annual cap.
| Capacity Factor | Fuel | Annual CO2 (one plant) | vs. 170,820 t Cap |
|---|---|---|---|
| 100% | Natural gas | ~1,395,000 t | 8.2× over |
| 100% | Diesel | ~2,042,000 t | 12.0× over |
| 25% (projected) | Natural gas | ~349,000 t | 2.0× over |
| 25% (projected) | 80% gas / 20% diesel | ~389,000 t | 2.3× over |
| 15% | Natural gas | ~209,000 t | 1.2× over |
| 12% | Natural gas | ~167,000 t | Just under cap |
At any capacity factor above approximately 12% on natural gas (or ~8% on diesel), the plants exceed the federal cap. The regulation does allow Canadian offset credits, but they are capped at an additional 35 t/GWh (capacity-based), adding only ~92,000 tonnes to the allowance. Even with maximum offsets, a 300 MW plant at 25% CF on gas still exceeds the limit by approximately 86,000 tonnes.
These plants cannot operate at the levels the grid requires without the exemption.
To qualify as a "planned unit," a project must meet four milestones by December 31, 2025:
| Milestone | CER Deadline | What Happened |
|---|---|---|
| EA information submitted to relevant authority | Dec 31, 2025 | EARDs registered Dec 22, 2025 - 9 days before deadline |
| Proponent owns or leases the site land | Dec 31, 2025 | IESO-NS acquired land options before any proponent was selected |
| Permit application info submitted | Dec 31, 2025 | Filed with EA registration |
| Equipment contracts ≥$10M signed | Dec 31, 2025 | No public information exists |
| Construction commenced (5th milestone) | Dec 31, 2027 | Pending |
The CER requires that contracts worth at least $10 million for equipment purchases be executed by December 31, 2025 - three months before the draft RFP was even issued (March 10, 2026). No contract has been disclosed. No equipment purchase has been announced. No line item appears in any public document. The Tolling Agreement's confidentiality provisions and the RFP's $20,000 data room paywall prevent verification.
If this milestone was not met, the planned unit qualification may be invalid - and the project's legal basis for operating without emission limits may not exist.
This deadline explains every aspect of the process that community members have questioned:
If proper planning and fieldwork had been done - if environmental assessments had taken the normal 12–18 months, if community consultation had been meaningful, if a competitive site selection had been conducted - the December 31, 2025 deadline would have been missed. And without the exemption, these plants cannot operate at the levels the grid needs.
The planned unit exemption expires December 31, 2049. After that date, the emission intensity parameter drops to 0 t CO2/GWh - the regulation's target is net-zero electricity.
But the Tolling Agreement runs for 25 years from the commercial operation date (~2030) to an expiry date of June 30, 2055. IESO-NS can unilaterally extend to year 26 (June 30, 2056) and request extension to year 27 (June 30, 2057).
| Date | What Happens |
|---|---|
| ~2030 | Plants commissioned, begin operating |
| 2030–2049 | No emission cap applies - planned unit exemption active |
| Dec 31, 2049 | Planned unit exemption expires |
| 2050 | Emission cap drops to near-zero (offsets allow limited operation) |
| June 30, 2055 | Tolling Agreement base term ends - 6 years after exemption expires |
| June 30, 2056–2057 | With IESO extensions - 7–8 years past exemption |
The plants go from no emission cap to a near-zero cap overnight. The Tolling Agreement does not address how the plants will operate - or whether they can operate - after 2050. Capacity payments are owed whether the plants run or not. Three possible outcomes after 2050, all bad for ratepayers:
At 25% capacity factor with an 80/20 gas/diesel fuel mix, both plants combined would produce annually:
Over 20 years of unregulated operation, that is approximately 15.6 million tonnes of CO2 with no federal cap in place.
The Multi-Sector Air Pollutants Regulations (SOR/2016-151) regulate NOx from boilers and spark-ignition engines, but gas turbines operate on the Brayton cycle - they are explicitly outside the regulation's scope. The ECCC published guidelines in 2017 recommending NOx limits for gas turbines, but they are non-binding recommendations published under CEPA Section 54, not enforceable law.
On diesel backup fuel, the pollution profile is significantly worse: NOx is 2.7× higher than on gas, sulfur dioxide (SO2) - an acid rain precursor that is essentially zero on gas - is introduced, and particulate matter (PM2.5) is 2.7× higher. The RFP allows up to 25% of operating hours on diesel, but no enforceable regulatory condition caps diesel operating hours.
These plants cannot operate at their projected levels without the pollution exemption. And the entire rushed process - the pre-selected sites, the 9-days-before-deadline EA registrations, the undisclosed $10M equipment contracts, the compressed community consultation - was designed to qualify for that exemption before the window closed.
| What They Say | What's Actually Happening |
|---|---|
| "Fast-acting generation for reliability" | Plants that cannot operate at projected levels without a pollution exemption |
| "No time to waste" | The rush was to meet a Dec 31, 2025 exemption deadline - urgency the government created by transferring the procurement mid-stream |
| "Clean energy transition" | 600 MW of fossil fuel generation exempt from emission caps for 20 years, emitting ~15.6 million tonnes of CO2 |
| "Pathway to clean fuels" | Non-binding language; NS Power's own modelling rejected hydrogen as uneconomic |
| "25-year contract" | Contract outlives the exemption by 6–8 years with no plan for compliance |